Exhibit 99.1
February 15, 2008
Energy Partners, Ltd.
201 St. Charles Avenue, Suite 3400
New Orleans, Louisiana 70170
Gentlemen:
At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of Energy Partners, Ltd. (EPL) as of December 31, 2007. The subject properties are located in the state and federal waters offshore Louisiana and Texas. The income data were estimated using the Securities and Exchange Commission (SEC) requirements for future price and cost parameters.
The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2007 were used in the preparation of this report as required by SEC rules; however, actual future prices may vary significantly from December 31, 2007 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interest of
Energy Partners, Ltd.
As of December 31, 2007
| Proved | ||||||||||||
| Developed | Total Proved | |||||||||||
| Producing | Non-Producing | Undeveloped | ||||||||||
Net Remaining Reserves | ||||||||||||
Oil/Condensate – Barrels | 111,000 | 409,600 | 55,000 | 575,600 | ||||||||
Gas – MMCF | 5,295 | 8,415 | 2,193 | 15,903 | ||||||||
Income Data | ||||||||||||
Future Gross Revenue | $ | 47,308,500 | $ | 96,860,800 | $ | 21,143,300 | $ | 165,312,600 | ||||
Deductions | 18,145,700 | 15,857,700 | 10,449,600 | 44,453,000 | ||||||||
Future Net Income (FNI) | $ | 29,162,800 | $ | 81,003,100 | $ | 10,693,700 | $ | 120,859,600 | ||||
Discounted FNI @ 10% | $ | 27,726,000 | $ | 63,316,900 | $ | 9,637,000 | $ | 100,679,900 | ||||
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.
| 1200, 530 8TH AVENUE, S.W. | CALGARY, ALBERTA T2P 358 | TEL (403) 262-2799 | FAX (403) 262-2790 | |||
| 621 17TH STREET, SUITE 1550 | DENVER, COLORADO 80293-1501 | TEL (303) 623-9147 | FAX (303) 623-4258 |
Energy Partners, Ltd.
February 15, 2008
Page 2
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries for Windows, a copyrighted program of Landmark Graphics. The program was used solely at the request of EPL. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions comprise the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Gas reserves account for approximately 67 percent and liquid hydrocarbon reserves account for the remaining 33 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form as follows.
| Discounted Future Net Income As of December 31, 2007 | |||
Discount Rate Percent | Total Proved | ||
| 5 | $ | 109,767,300 | |
| 15 | $ | 93,132,600 | |
| 20 | $ | 86,785,300 | |
| 25 | $ | 81,386,100 | |
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
Theproved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definition of proved reserves is included under the tab “Petroleum Reserves Definitions” in this report.
Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled.
The various reserve status categories are defined under the tab “Petroleum Reserves Definitions” in this report. The developed non-producing reserves included herein are comprised of the shut-in and behind pipe categories.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Energy Partners, Ltd.
February 15, 2008
Page 3
Estimates of Reserves
In general, the proved producing reserves included herein were estimated by performance methods which utilized various extrapolations of historical production and pressure data available through December 2007; however, certain of the producing reserves were estimated by the volumetric method in those cases where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The proved non-producing and undeveloped reserves included herein were estimated by the volumetric method which utilized all pertinent wells and 3-D seismic data available through December 2007.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.
Future Production Rates
Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by EPL.
The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.
Hydrocarbon Prices
EPL furnished us with hydrocarbon prices in effect at December 31, 2007 which take into account SEC and Financial Accounting Standards Board (FAS B) rules regarding current market prices.
In accordance with FASB Statement No. 69, December 31, 2007 market prices were determined using the daily oil price or daily gas sales price (“spot price”) adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2007 were not considered in this report.
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Energy Partners, Ltd.
February 15, 2008
Page 4
Costs
Operating costs for the leases and wells in this report are based on the operating expense reports of EPL and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, this includes an appropriate level of corporate general administrative and overhead costs and for non-operated properties include the COPAS overhead costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.
Development costs were furnished to us by EPL and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage are significant. The estimates of the net abandonment costs furnished by EPL were accepted without independent verification.
Current costs were held constant throughout the life of the properties.
General
Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 161 present our estimated projection of production and income by years beginning January 1, 2008, by state, field, and lease or well.
While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
The estimates of reserves presented herein were based upon a detailed study of the properties in which EPL owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. EPL has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by EPL were accepted without independent verification. The estimates presented in this report are based on data available through December 2007.
EPL has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.
Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Energy Partners, Ltd.
February 15, 2008
Page 5
This report was prepared for the exclusive use and sole benefit of Energy Partners, Ltd. and may not be put to other use without our prior written consent for such use. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.
| Very truly yours, |
RYDER SCOTT COMPANY, L.P. |
 |
Stephen E. Gardner, P.E. Petroleum Engineer |
| SEG/pl |
| Reviewed by: |
 |
| John E. Hamlin, P.E. |
| Managing Senior Vice President |
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
SECURITIES AND EXCHANGE COMMISSION
INTRODUCTION
Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission.
Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows:
Proved oil and gas reserves.Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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(B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbon s controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;
(B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves.Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves.Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staffs view on specific questions pertaining to proved oil and gas reserves.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test, (extracted from SAB-35)
In determining whether “proved undeveloped reserves” encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? ... The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership, (extracted from SAB-35)
The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions, (extracted from SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission’s official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws.
SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)
In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing.
Producing.Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 4
Non-Producing.Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS